Various types of rotary drill bits, reamers, stabilizers and other downhole tools may be used to form a borehole in the earth. Examples of such rotary drill bits include, but are not limited to, fixed cutter drill bits, drag bits, PDC drill bits, matrix drill bits, roller cone drill bits, rotary cone drill bits and rock bits used in drilling oil and gas wells. Cutting action associated with such drill bits generally requires weight on bit (WOB) and rotation of associated cutting elements into adjacent portions of a downhole formation. Drilling fluid may also be provided to perform several functions including washing away formation materials and other downhole debris from the bottom of a wellbore, cleaning associated cutting elements and cutting structures and carrying formation cuttings and other downhole debris upward to an associated well surface.
Some prior art rotary drill bits have been formed with blades extending from a bit body with a respective gage pad disposed proximate an uphole edge of each blade. Gage pads have been disposed at a positive angle or positive taper relative to a rotational axis of an associated rotary drill bit. Gage pads have also been disposed at a negative angle or negative taper relative a rotational axis of an associated rotary drill bit. Such gage pads may sometimes be referred to as having either a positive “axial” taper or a negative “axial” taper. See for example U.S. Pat. No. 5,967,247. The rotational axis of a rotary drill bit will generally be disposed on and aligned with a longitudinal axis extending through straight portions of a wellbore formed by the associated rotary drill bit. Therefore, the axial taper of associated gage pads may also be described as a “longitudinal” taper.
Gage pads formed with a positive axial taper may increase steerability of an associated rotary drill bit. Drag torque may also be reduced as a result of forming a gage pad with a positive axial taper. However, lateral stability of an associated rotary drill bit relative to a longitudinal axis extending through a wellbore being formed by the rotary drill bit may be reduced. Also, the ability of the associated rotary drill bit to maintain a generally uniform inside diameter of the wellbore may be reduced.
For other applications gage pads have been offset a relatively uniform radial distance from adjacent portions of a wellbore formed by a associated rotary drill bit. Exterior portions of such gage pads may be generally disposed approximately parallel with an associated bit rotational axis and adjacent portions of a straight wellbore. The amount of offset between exterior portions of such gage pads and adjacent portions of a straight wellbore will typically be relatively uniform. For some applications gage pads have been formed with a relatively uniform radial offset or uniform reduced outside diameter between approximately 1/64 of an inch to 4/64 of an inch as compared to a nominal diameter of the associated rotary drill bit.
Providing gage pads with an offset from an associated nominal bit diameter or undersizing gage pads may increase steerability of an associated rotary drill bit. However, lateral stability relative to a longitudinal axis of an associated wellbore and ability of the rotary drill bit to ream or form the wellbore with a generally uniform inside diameter may be reduced.